Natural Gas Prices and Market Fundamentals

CRS Report for Congress
Natural Gas Prices and
Market Fundamentals
Updated December 8, 2004
Robert Pirog
Specialist in Energy Economics and Policy
Resources, Science, and Industry Division

Congressional Research Service ˜ The Library of Congress

Natural Gas Prices and Market Fundamentals
Intermittently high, volatile natural gas prices since 2000 have raised concern
among all types of consumers. Residential customers have seen gas bills increase
dramatically during the heating season. Industrial consumers have seen costs
increase, which reduces their competitiveness. Because the price of natural gas at the
consumer level is a mixture of market forces and regulation, explaining the behavior
of price can be difficult.
Debate in the 108th Congress concerning the energy bill (H.R. 6), considered
provisions which are intended to improve long term natural gas supplies in theth
United States. Other issues are likely to be brought before the 109 Congress for
consideration. This paper analyzes the short term forces which influence the natural
gas market.
The Energy Information Administration has developed a metric called the
effective capacity utilization rate as a framework for analyzing the economics of the
natural gas market. This measure has been shown to be correlated with the price of
natural gas. When as the effective capacity utilization rate attains high levels (90%
and above) it becomes increasingly likely that tight market conditions will yield high
As a result of the Natural Gas Policy Act of 1978 (P.L. 95-621) and subsequent
legislation in 1989 and 1992 (P.L. 101-60 and P.L. 102-486) the wellhead price of
natural gas is market determined. Pipeline rates are federally monitored and
distribution charges are regulated at the state level. Price variability centers on the
wellhead price as well as the price determined in futures markets.
Price spikes have occurred in two of the past three heating seasons. Whether
severe weather causes price increases depends on the tightness of the market as
measured by the effective capacity utilization rate. The same level of demand could
lead to very different price results if the effective capacity utilization rate is high or
A variety of factors can affect the effective capacity utilization rate. Since short
run supply adjusts to meet demand, the weather will be an important determinant.
The relationship between natural gas prices and investment in exploration,
development and production is an important factor in determining productive
capacity. The availability of stored gas and imported gas become vital to price
stability as the effective productive capacity exceeds 90%.
In the very short term there appears to be little that can be done from a policy
perspective to alter the fundamental economics of the natural gas market. In the
longer term, policies that slow demand growth and/or encourage the growth of
supply, either from domestic or foreign sources could be effective.
This report will be updated as events warrant.

Background ......................................................1
Price Behavior....................................................3
Factors Affecting ECUR and Price....................................6
Weather .....................................................6
Investment and Price...........................................8
Gas Imports..................................................9
Stored Gas...................................................9
Policy Considerations.............................................11
List of Figures
Figure 1. Lower-48 States Effective Capacity Utilization and Gas Prices,
1987-2001 ...................................................3
Figure 2. Lower-48 States Monthly Dry Gas Production Rate and
Effective Productive Capacity and Utilization, 1985-2003..............4
Figure 3. Wellhead Price of Natural Gas...............................5
Figure 4. Natural Gas Seasonal Demand...............................7
Figure 5. Working Gas in Underground Storage Compared With
5-year Range................................................10
List of Tables
Table 1. Natural Gas Prices..........................................2

Natural Gas Prices and Market
After a decade of low natural gas prices, market prices spiked during the winters
of 2000-01 and 2002-03 and remained high through the winter of 2003-04. Prices
averaged $4.97 per thousand cubic feet (mcf) for the year 2003, and rose to an
average level of $5.41 for the first eight months of 2004. Futures prices observed
through November, 2004 suggest that natural gas prices might remain high during the
winter heating season of 2004-05. Natural gas price trends through 2003 suggested
that the market might be experiencing greater volatility than in the past. The
sustained high prices observed in 2004 suggest that the period of volatility might be
over and prices might remain at levels over $5.00 per mcf for the next year, or more.
The wellhead price of natural gas is market determined, the result of a complex
interaction of forces which influence both the demand and supply of gas. Among
those forces are such imponderables as winter weather as well as the actual amount
of surplus producible natural gas, if any, and the availability of imported gas. Market
dynamics are complicated because the same potentially destabilizing event may have
very different effects on the price, depending on the initial state of the market.
The Energy Information Administration (EIA) has developed a metric to
evaluate the effect of these complex interactive forces, based on effective productive
capacity. Called the effective capacity utilization rate (ECUR), it establishes a
conceptual framework with which to analyze the natural gas demand and supply
balance and price.
This report analyzes the linkage between the concepts of effective productive
capacity, the ECUR, increases in the price of natural gas, and the potential for higher
prices in the 2004-05 heating season. Additionally, the report addresses policy
options, both in the short and longer terms, that have been publicly discussed.
The natural gas market is composed of three major components on the supply
side; producers, pipelines, and local distribution companies. The price of natural gas
paid by consumers is layered, in the sense that the wellhead price paid to producers
forms a baseline. Pipeline transportation costs are then added, which yields the city
gate price. Finally, local distribution companies add additional charges to yield the
prices actually paid by consumers. Consumer markets themselves are divided into
segments, each of which tends to pay a different, in many cases a significantly
different, price. Residential consumers pay the highest prices, followed by

commercial, industrial, and electricity users. Table 1 shows the relationship between
these prices in recent months.
The residential prices presented in Table 1 represent an increase of 7% over
residential prices for a comparable period in 2003. The most recent EIA natural gas
price data available at the time of this report was August 2004. On the New York
Mercantile Exchange (NYMEX), natural gas for delivery in December 2004 was
trading at $6.80 per mcf and January and February 2005 natural gas was trading at
over $7.50 per mcf.1
Table 1. Natural Gas Prices
5/04 6/04 7/04 8/04
Wellhead Price5.635.855.605.36
City Gate Price6.486.926.686.45
Residential Price11.6013.0513.4113.78
Commercial Price9.039.579.489.47
Industrial Price6.276.706.246.19
Source: EIA Natural Gas Price Data, measured as dollars per mcf. Natural Gas Monthly,
October, 2004, Table 4, p.8.
In addition to multiple prices faced by consumers, other prices are key variables
for supply and policy decisions. The wellhead price of natural gas, as noted in this
report, is competitively determined by market forces. This was not always the case.
The process of natural gas price deregulation began in 1978 when the Natural Gas
Policy Act (P.L. 95-621) became law. Under the Natural Gas Policy Act, nearly all
price controls were phased out by the end of 1984.2
The spot price of natural gas is recorded at a transportation hub, the largest in
the United States being Henry Hub in Louisiana, and is generally somewhat higher
than the wellhead price because it includes some processing and transportation costs.
Natural gas futures contract trading on the NYMEX establishes forward prices for
natural gas, and allows market participants to hedge short and medium term price
risk. The NYMEX future price is determined by the interaction of traders who have
business interests in the real, physical natural gas market, and financial traders who
speculate on the market. Natural gas is also traded by numerous brokers and other
entities for physical delivery at a number of local markets.

1 Gas prices on the NYMEX are quoted for delivery at Henry Hub, Louisiana, and are not
equivalent to wellhead prices. Henry Hub prices include some processing costs, as well as
transportation costs to Henry Hub from the producing field.
2 Additional legislation adopted in 1989 and 1992 completed the process of deregulation,
(P.L. 101-60 and P.L. 102-486).

Interstate pipeline rates are not directly regulated and their pricing structure
largely reflects open access for shippers and market pricing. The Federal Energy
Regulatory Commission (FERC) monitors pipeline tariffs to assure “just and
reasonable” pricing, and has intervened in a number of tariff situations. The city gate
price includes the addition of these pipeline transportation charges.
Residential and small commercial consumers buy gas from a local distribution
company, which delivers gas from a long-haul pipeline to the customer’s premises.
Local distribution companies are regulated by state public service commissions, who
set distribution charges. The price data in Table 1 indicates that residential prices
have recently been almost double city gate prices in 2004. The price premium paid
by residential and commercial consumers reflects the high fixed cost associated with
distribution of their supply, as well as the added cost of small volume purchases.
Price Behavior
The EIA defines effective productive capacity as the maximum production
available from natural gas wells, allowing for limitations in the production, gathering,
and transportation systems.3 The effective capacity utilization rate (ECUR) is the
ratio of actual production to effective productive capacity. Surplus capacity is the
difference between effective productive capacity and actual production.
Figure 1. Lower-48 States Effective Capacity Utilization
and Gas Prices, 1987-2001
Figure 1 shows, for monthly data over the period 1987 to 2001, that the average
wellhead price has stayed below $3.00 per mcf whenever the ECUR was below 90%.
The data also show how upwardly volatile natural gas prices can be as the ECUR
rises above 90%. The correlation between high values of the ECUR and high prices

3 Energy Information Administration, Natural Gas Productive Capacity for the Lower-48
States, 1985-2003, 2003, p.1.

suggests that when the ECUR is above 90%, conditions are in place that are
consistent with high, volatile natural gas prices.
Figure 2. Lower-48 States Monthly Dry Gas Production
Rate and Effective Productive Capacity and Utilization, 1985-2003
Figure 2 shows the history of the ECUR, capacity and production since 1985.
Several trends are noticeable in the data. Productive capacity has declined since the
late 1980s, but appears to have remained stable since 1993. Actual production has
trended up from 1985 to 1995 and has been relatively stable since then. These two
trends, taken together, drove the ECUR to 90% or higher levels for almost all of the
past eight years.
An ECUR in excess of 90% indicates that available natural gas output is nearly
fully allocated to meeting demand. Any further increase in demand, or disruption of
supply, can only be met through extraordinary draws on existing gas wells, increased
draws from storage, or increased imports. All of these alternatives suggest that prices
for the consumer are likely to rise. If these sources are unavailable for expansion the
price could rise dramatically, and supply disruption might occur.
As part of the market adjustment to higher prices, increased development
drilling could take place, but exploration and development does not immediately
result in gas on the market. The EIA estimates that there is a lag of between 6 and 18
months between an increase in natural gas prices and an increase in developmental
drilling and ultimately higher production.4 The declining productivity of U.S. fields
is also a factor. According to one industry observer, “it takes approximately 2.5
times more active rig capacity to produce the same amount of gas as just eight years

4 Energy Information Administration, U.S. Natural Gas Markets: Mid-Term Prospects for
Natural Gas Supply, December 2001, p.xiii.

ago.”5 Alternatively, when the ECUR is below 90%, any requirement for additional
supply can be quickly brought to the market by increasing production from existing
Figure 3. Wellhead Price of Natural Gas
Source: U.S. Energy Information Administration, derived from data available at
[ ng/hist/n9190us3A.htm.]
Figure 3 shows the history of the wellhead price of natural gas from 1973
through 2003. Again, several trends are noticeable. The first run up in prices, from
1973 to the mid 1980s was the result of price deregulation in a market where supply
was not abundant, demand–after years of regulated prices–was strong, and oil prices
were high, as a result of the Arab oil embargo of the United States in 1973-74, and
the Iranian political upheaval of the late 1970s. Prices declined after 1985–as did
demand–and the United States entered a decade long period of relatively low, stable
prices. During this period, use of natural gas as an abundant, cheap, clean fuel was
promoted. Increasing demand, in conjunction with the supply trends shown in
Figure 2, has resulted in the ECUR remaining at, or above, 90% since 1995. These
conditions set the stage for the gas price increases and price volatility experienced
since 2000.
An interesting break in the pattern of the Figure 2 data is associated with the
sharp price increases of the winter of 2000-01. As can be seen in Figure 2, the
ECUR achieved very high values during this period. When coupled with the low
temperatures of that winter, the result was high prices that set off a boom in
exploration and drilling. While only 496 rotary drilling rigs, on average, were
drilling for natural gas in 1999, that number increased to 720 in 2000 and rose to 939

5 Joseph P. Mathew, LNG: What is it all About?, Energy Pulse, November 27, 2002. p.4.

for 2001. As the resulting production entered the market in 2002 (6 to 18 months
later) the ECUR fell below 90% in 2002 and the price of natural gas fell.6 The lower
price, however, resulted in lower developmental drilling and set the stage for sharp
price increases in the winter of 2002-03. As prices declined in 2002, as seen in
Figure 3, the drilling rig count also declined, to 691. The ECUR, reflecting the
lower anticipated increments to production from reduced exploratory drilling, again
rose above 90%, and price increases beginning during the winter of 2002-03
Drilling activity may be responding to 2003's higher prices. The EIA reported
that the average monthly drill rig count for 2003 was 872, with the count running
over 900 per month from June to December. The nine month average drilling rig
count for 2004 is 1009, and has been on a path of steady monthly increases since
January 2004.7 Whether the recent increase in drilling activity results in large enough
supply increases to allow the price of natural gas to fall depends on the exploration
success rate, the size of the fields found, and the degree to which existing producing
wells show output declines.
Factors Affecting ECUR and Price
Any factor that increases demand or decreases supply will increase the ECUR.
When the ECUR is below 90% extra pressure on the market is likely to result in
higher production. Once the ECUR rises to 90% or above, timely increases in
production are less available and pressure on the market manifests itself as higher
prices. Higher prices create incentives that eventually could cause price increases to
moderate, although new sources may require higher prices to satisfy investment
The demand for natural gas exhibits a seasonal pattern even when the weather
is normal. Figure 4 shows the typical pattern, which is characterized by seasonal
demand peaks. Since seasonal patterns are repetitive, suppliers, attempting to
accommodate consumers, accumulate quantities of gas in storage facilities in the
traditional off-peak season for release during the heating season.

6 Data for drilling rigs searching for natural gas was obtained from the Energy Information
Administration, Monthly Energy Review, October,2004, Table 5.1, p.83.
7 Ibid.

Figure 4. Natural Gas Seasonal Demand
Source: U.S. Energy Information Administration available at
[ ht t p: / / www.ei pub/ oi l _ga s/ nat ur a l _ga s/ pr esen t a t i o n s / 2004/searuc/searuc_files/
If the seasonal demand pattern is accentuated by extreme weather conditions,
the stored quantities of natural gas might not be sufficient, setting the stage for price
increases if the ECUR is high. For example, as we approached the heating season of

2002-03, stored gas was at a normal level of approximately 3 trillion cubic feet (tcf).

Below average temperatures early in the winter quickly drove stored quantities down
to low levels, which set the stage for the price increases that followed.
If the ECUR remains high, as is likely, and a cold winter weather pattern
repeats, the limited amount of stored gas, as well as the unresponsiveness of both
supply and demand to real time price variations at the consumer level, could well
bring about another price spike in the winter of 2004-05.
The seasonal pattern of natural gas demand is being altered by its growing use
by electric power generators. Power generators expanded their demand for natural
gas by 36% over the period 1997-2002. The EIA expects that over the long term
forecast period, 80% of new electricity generation will be fueled by natural gas,
continuing the strong growth of the last several years. Not only is electricity demand
adding to total natural gas demand, but the pattern of peak demand might interfere
with traditional gas demand cycles. The demand for natural gas for electricity
generation peaks in the months June through October when space heating demand
from residential and commercial customers is low, but when storage facilities
replenish their stocks. As a result, it might be the case that the ECUR is pushed to
higher levels, year round. Competition for summer supplies could cause short falls

in storage quantities, create price pressures that squeeze out price sensitive industrial
customers, or force higher electricity rates or even shortages to the system.8
Investment and Price
As discussed earlier in this report, when the ECUR is 90% or above, the ability
of the industry to respond to increased demand with expanded supply from existing
wells is limited, causing price to increase quickly. However, the higher prices do
provide an incentive to begin the process of drilling new wells and exploring for new
supplies. The resulting supply increase will tend to cause price to fall as productive
capacity is enhanced, reducing the ECUR.
The nature of this relationship in the natural gas industry can, under some
circumstances, lead to a cycle of unstable boom and bust feared by those investing
in gas production. Taken to its extreme, this could lead to chronic under-investment
in gas production and stagnant supply.
Higher prices for natural gas justify investment in exploratory drilling by
increasing the value of the expected cash flow derived from the new production. In
an efficiently operating market, a sustained, marginal increase in price is supposed
to elicit a marginal increase in production. In natural gas, when the price rises,
hundreds of extra rigs drill thousands of additional wells. Historical averages suggest
that about 80% of these efforts will be successful and yield some new production.
Once a well is brought into production, there is little economic rationale for not
producing at full capacity. As a result, the market moves to a condition of excess
supply as new production begins, causing a fall in the price. The reduced price
brings a disincentive to invest in exploratory drilling, which leads to a period of
stable supply setting the stage for a rising ECUR a tightening market balance and
rising prices.
A key factor in the ability of the rate of investment in exploration to affect the
ECUR is the degree to which existing wells deplete, or yield declining output levels.
For example, the EIA expected that in 2003 the estimated effective productive
capacity of the U.S. natural gas industry would be approximately 57 billion cubic feet
per day (bcf/d). For 2003, production was expected to be approximately 51.4 bcf/d,
leaving a surplus of 5.6 bcf/d, or about 10%. To demonstrate how this balance
depends on new drilling and expansion of capacity, the EIA estimated that 25% of
effective productive capacity comes from wells one year old or less. The two largest
suppliers of U.S. natural gas, Texas and the Gulf of Mexico, derive 30% of their
production from wells one year old or less. If drilling were to stop in the U.S., all
surplus capacity would disappear in less than one year.
In 2001, the incentive of high prices led to 22,800 well completions that resulted
in increased productive capacity. Only 17,800 wells were completed in 2002 and
productive capacity declined. If, as this recent data suggests, the potential for a
boom/bust investment cycle may be developing in the natural gas industry, the result

8 Long term forecast estimates are from the EIA , Annual Energy Outlook 2003.

will be brief periods of low prices and plentiful supply followed by periods of high
prices and potential physical shortages.9
Gas Imports
The measures analyzed in the EIA study of effective productive capacity only
refer to resources in the lower 48 states. As the U.S. natural gas market develops,
this restriction will become less appropriate. The U.S. natural gas market is well
integrated with the Canadian market. Imports of Canadian natural gas have long
been an important supply source when U.S. consumption exceeded U.S. production
and available stock draw down. Imports of natural gas from Canada, all via pipeline,
reached over 3.7 tcf per year in 2001 and 2002, but declined to less than 3.5 tcf in
2003. Canadian gas fields, like those in the United States, may be unable to easily
expand output without the development of new fields.
An additional source of imports might be liquefied natural gas (LNG).10 The
U.S. has four operational (or near operational) LNG receiving facilities with an
annual operational send-out capacity of 1.4 tcf per year after all planned expansions
are completed.11 The critical issue concerning LNG is cost. Although the cost of a
complete LNG facility has fallen substantially (30%) due to economies of scale and
enhanced technology over the last decade, LNG cost is greater than most
conventional gas from wells in the lower 48 states.12 As a result, dependence on
LNG may safeguard the nation from physical shortage by building a new, higher,
baseline price into the market.
Stored Gas
The volume of gas held in storage is a critical element in evaluating the
possibility of price volatility. If storage volumes are below normal as the winter
heating season begins, and the ECUR is above 90%, the potential for elevated prices
must be considered to be high.

9 Energy Information Administration, Natural Gas Productive Capacity for the Lower-48
States, 1985-2003, 2003, p.1.
10 LNG is natural gas that has been chilled to a liquid state for shipping on a specially
designed tanker. Once it reaches its destination it is heated to transform it back to a gas.
At that point it is injected into the pipeline system, identical to natural gas from the
11 Energy Information Administration, U.S. LNG Markets and Uses, January, 2003, Table

1, p.6.

12 James T. Jensen, The LNG Revolution, The Energy Journal, Vol. 24, No.2, 2003, p.31.

Figure 5. Working Gas in Underground Storage Compared
With 5-year Range
Notes: A weekly record for March 8, 2002, was linearly interpolated between the derived weekly
estimates that end March 1 and the initial estimate from the EIA-912 on March 15. The shaded area
indicates the range between the historical minimum and maximum values for the weekly series from
1999 through 2003.
Source: Weekly storage values from March 15, 2002, to the present are from Form EIA-912, “Weekly
Underground Natural Gas Storage Report.” Values for earlier weeks are from the Historical Weekly
Storage Estimates Database, with the exception of March 8, 2002.
Figure 5 shows the variability of storage volumes of working gas. Stored
volumes totaled 2.7 tcf at the end of the 2000 refill season. The severe temperatures
during the heating season of 2000-01 drew this down to a low of 742 billion cubic
feet (bcf) in March of 2001. In contrast, at the end of the 2001 refill season, the
stored volume was 3.1 tcf, but the heating season was characterized by more
moderate temperatures and the stored volume did not fall below 1.5 tcf, double the
quantity of the previous year. At the end of the 2002 refill season the stored volume
was again 3.1 tcf, but by March of 2003 this had been reduced to 735 bcf, lower than
the low point of the 2000-01 season. The 2003-04 refill season started with volumes
almost 40% below their five year averages. Storage injection increased in the first
six months of 2003, so that by mid-July 2003 storage volumes totaled 1.9 tcf, only
12% below the five year average. At the end of July 2003, total working gas storage
was approaching 2.5 tcf. By November 2003, storage volumes approached the target
of approximately 3.0 tcf in preparation for the onset of the heating season.
As shown in Figure 5, in November 2004 working gas storage levels were
above their five year average, suggesting that adequate supplies were available. The
EIA reported that by November 26, 2004 stocks in the lower 48 states totaled about

3.3 tcf, about 0.2 tcf more than at the same time in 2003.13 Given this storage report,

it would seem unlikely that the current high futures prices observed on the NYMEX
could be supported by uncertainties related to available stocks.
Policy Considerations
The potential effects of high, volatile natural gas prices on both the national
economy as well as individual consumers is not insignificant. High, sustained levels
of natural gas prices can act as a drag on economic growth. As with oil price shocks
in the past, high natural gas prices can constitute a classic supply side shock which
reduces output and productivity growth. If severe enough, a shock of this type can
increase unemployment and cause inflation in the short term.
On the level of individual consuming sectors, high natural gas prices negatively
affect specific industrial users who make heavy use of natural gas in their production
process, which makes them uncompetitive. Residential users might have difficulty
paying their winter heating bills, forcing them to choose between adequate home
heating and other necessities.
In the very near term little can be done to affect natural gas prices, except
through market intervention in the form of price controls, mandatory conservation,
and prioritized rationing. The conditions that will determine market balance for 2004
and 2005 are largely in place, with the major exception of the weather. To help
mitigate the effects of possible price spikes this winter, aid to low income gas
consumers through the Low Income Home Energy Assistance Program (LIHEAP)
could be increased.14
Much can be done to alter the demand and supply characteristics of the natural
gas market in the long term. Conservation, expansion of LNG use, access to areas
not currently available for exploration, and new pipeline construction, among others
can be debated. Any of these options will take significant time to implement and
must be considered in a long term context. None of them are likely to have
significant influence on prices over the next six months to one year.

13 Energy Information Administration, Weekly Natural Gas Storage Report, December 2,


14 The American Gas Association reports that LIHEAP served abut 4 million households in
2003, only 15% of those eligible. Carl L. English, on behalf of the American Gas
Association, testimony before the U.S. House of Representatives Energy and Commerce
Committee, June 10, 2003, p.14.